Why Oil Pipelines Have Always Been A Challenge For Alberta Producers – David Yager

July 17, 2018 by EnergyNow Media

By David Yager

Oilfield Services Executive Advisory – Energy Policy Analyst

Canada’s prairie provinces are not an ideal location from which to export large quantities of oil and gas. The Western Canadian Sedimentary Basin (WCSB) is on the eastern flank of the Rocky Mountains which run parallel to the Pacific Ocean. The western fringe of the basin is about 1000 km. from the coast. The mountainous terrain between the resources and tidewater is the most rugged in the country.

The most underpopulated regions of North America are north, south and east of the WCSB. The bigger markets of central Canada, U.S. Midwest, California, the Gulf Coast and the East Coast are further away than the ocean.

The good news is geological history put a lot of hydrocarbons in the WCSB. The bad news is the resources are in the wrong place, the customers are in the wrong place, or both.

Today, getting more pipe built to move product remains one of the industry’s greatest challenges, front page news for most of this decade. This problem is not new, just different. The anti-carbon movement has been very successful in convincing people that mankind must discontinue the use of fossil fuels or the planet will face irreversible and devastating damage from climate change. Pipeline approvals have become ground zero for carbon energy’s opponents. It is clearly working.

But Alberta or Canada without its carbon-resource industries would be an economic disaster. Carbon’s critics routinely make optimistic predictions about a promising future in renewable energy without specifics, timelines or cost. There are no practical substitutes on a large scale for coal, oil or natural gas. Global consumption, current and forecast, verify this. Your writer is very concerned about the consequences of this increasingly one-sided debate. So I’m researching a book about how we got into this situation and where it could take us.

History often reveals more about the present and future than it gets credit for. Following is summary of what my recent research has unearthed about oil pipelines in the past 70 years.

The oil sands have intrigued Europeans for three centuries. Samples arrived at York Factory, a Hudson’s Bay Company fur trading post, in 1719. But commercial separation of the oil from the sand remained elusive. Discoveries at Turner Valley in 1914 (gas), 1924 (gas and naphtha) and 1936 (crude oil) caused great excitement at the time. An oil pipeline was built to Calgary and refineries constructed. These assets played a significant role supplying gasoline and aviation fuel to industry and military during the Second World War.

In 1958 Eric Hanson, Associate Professor of Economics at the University of Alberta, wrote a book titled Dynamic Decade. In it Hanson analysed the massive economic impact the Leduc and subsequent discoveries had on Alberta’s economy. He wrote, “Transportation costs have a great effect on the degree to which the resource potential of Alberta is used…without pipeline transportation the oil and gas potential would be largely untouched and applied mainly to serve a small prairie market”.

Which is all there was. Hanson explained, “Before Turner Valley became a producer of crude oil in 1936, most of the crude used by Alberta and Saskatchewan refineries came from the U.S., much of it from the Cutbank field in Montana. By 1941 Turner Valley had replaced imported crude in these two provinces. Prior to 1950, the only oil pipelines in the country were in Alberta and near Sarnia. Oil was discovered in southern Ontario in 1875.

While the various Turner Valley oil booms were interesting, the ten years from 1946 to 1956 rewrote history, an economic boom of national significance. This was the foundation of Canada’s modern petroleum industry.

The numbers are amazing. Hanson reported in 1946 Alberta’s oil production averaged 19,450 b/d. Ten years later it was up to 394,000 b/d, twenty times higher. In all the years leading up to Leduc, Alberta’s Petroleum and Natural Gas Conservation Board (PNGCB, predecessor of the ERCB and today’s Alberta Energy Regulator) reported “virgin” oil reserves of 157 million barrels had been discovered, over half of which was already produced. The province exited 1956 with proven and recoverable reserves of 3.6 billion barrels, 83% awaiting recovery.

Two things were obvious. Sufficient reserves had been identified to warrant pipelines to larger markets and construction had to begin immediately to justify continued investment. After multiple markets including Sarnia and Chicago were studied, the proponents concluded Superior, Wisconsin would be suitable. On the western end of Lake Superior, the eastern terminus would connect Alberta to the U.S. Midwest and allow oil to be shipped by tanker to Sarnia.

Hanson wrote, “The Interprovincial Pipe Line Company (IPL) was formed in early 1949 and Imperial Oil (discoverer of Leduc and Redwater and pipeline proponent) assumed a minority interest of one third. The Canadian Parliament passed the Pipe Lines Act in April 1949, giving the Board of Transport Commissioners (National Energy Board not created until 1959) jurisdiction over pipeline routes, operations and tariffs. Shortly afterward the Interprovincial Company was created by a special act of parliament. The Board of Transport Commissioners approved construction of the Edmonton-Regina section in June and the section to Gretna, Manitoba, on the international border, in September. A wholly owned subsidiary of Interprovincial, the Lakehead Pipe Line Company, was formed to build and operate the American section from Gretna to Superior, Wisconsin.”

IPL finished construction of the 1,817 km. pipeline in late 1950. It would have been done sooner except for a pipe shortage. Capacity was 95,000 b/d. The line also supplied refineries in Regina and Winnipeg. An extension to Sarnia was completed in 1953. This added another 1,020 km. of pipe, bringing the total from Edmonton to Sarnia to 1,837 km. By 1956 the system had been expanded to a capacity of 265,000 b/d.

Let’s review what you just read. In just 20 months oil producers and the governments of Alberta, Saskatchewan, Manitoba, Minnesota, Wisconsin, Canada and the United States agreed this oil pipeline was useful and important, and cleared the way for financing, construction and commissioning. IPL is now Enbridge and the original IPL route has been expanded several times.

This is why we have a wealthy country and oil industry to argue about in the 21st century.

But there was still more oil than pipe. Expansion to west coast markets was also attractive. While the B.C. market was only 40,000 b/d, the Pacific Northwest states were consuming 250,000 b/d but with little refining capacity. Hanson wrote, “If only refineries could be built in Washington, it seemed entirely reasonable that Alberta crude could supplant a large part of the tanker shipments from California. The outbreak of the Korean War created a critical crude oil supply in the Pacific region. This gave impetus to proposals to pipe Alberta crude westward.”

Hanson continued, “…on March 21, 1951 the Trans Mountain Oil Pipe Line Company was incorporated by a special act of the Parliament of Canada”. The route was Edmonton to Burnaby, 1,155 km. via Jasper, the Yellowhead Pass and appropriate river valleys. Construction began in February of 1952 and was completed 19 months later in September 1953. Refineries in Washington were expanded and a new one built. Initial capacity of 150,000 b/d grew to 200,000 b/d a year later.

B.C.’s support was unequivocal. Local media carried excerpts from the B.C. regulator which wrote, “It is needless to state that the province of B.C. is desirous that no time be lost in establishing the pipe line. It is of great concern to the people of British Columbia that the line should be an all-Canadian route…to ensure that the people of British Columbia shall enjoy to the fullest extent the benefits to be derived from the development of Canada’s natural resources”.

Wow. But in the 1950s Canada was still a country, not a collection of increasingly myopic provincial nation-state wannabes.

Despite the construction of pipelines east and west – in lightning speed compared to modern times – oil discoveries were still outstripping takeaway capacity. Dynamic Decade reported that although “actual production” was up to 393,000 b/d by 1956, “potential production” was estimated by the PNGCB at 684,000 b/d had pipeline capacity been available.

Compared to today, the problem of more oil than pipe was much worse 50 years ago, at least percentage-wise.

The solution was “prorationing”, the only fair way to deal with this very political problem. Under prorationing all producers would be throttled back in a proportional manner. Reluctantly, it became the law of the land. No pipe and no better ideas.

Then along came the oil sands. Starting in 1944, the Alberta government financed an experimental separation plant at Bitumount north of Fort McMurray to prove this could be done commercially then attract private sector investment. By 1949 Bitumount was yielding 660 barrels per day. In 1953 a group from Toronto incorporated Great Canadian Oil Sands Limited (GCOS). Sun Oil Company had been aware of the oil sands since 1944 and acquired a promising lease in 1954. After making a deal with Sun Oil, in 1960 GCOS applied to build an oil sands production complex to produce 31,500 b/d, later increased to 45,000 b/d. It was approved and construction began in 1964. The plant commenced operations three years later. This included a pipeline to Edmonton to connect with existing transportation infrastructure. The oil sands were real.

However, pipeline takeaway capacity from Alberta remained challenged. In 1960 a consortium of companies that would later become Syncrude also applied to build an even larger plant to produce 100,000 b/d. But among conventional producers struggling with prorationing, having more oil sands come on stream in such large quantities would clobber their business. The government delayed even opening the Syncrude file until 1968.

The problem with oil sands mining is once the plant is running you can’t turn it off. This production is not suitable for prorationing. Cognizant of stiff opposition to unconventional oil, when GCOS was approved it was accompanied by a provincial decree that oil sands output would be limited to 5% of total crude production.

Feelings ran high. While lunching at the Petroleum Club in Calgary, Black Gold With Grit author J. Joseph Fitzgerald (who helped build GCOS then wrote a book about the oil sands in 1978) recalls being verbally attacked when a “Pete Club” member discovered Fitzgerald was one of “those guys from the tar sands”. The member claimed he was going to table a resolution with the club’s board of directors to deny oil sands producers membership, ensuring “none of your kind” would again be allowed in the building.

Despising the oil sands became a popular pastime this century. But it actually started over 50 years in Calgary ago for entirely different reasons.

In 1968 the regulator, as promised, reopened the Syncrude file. The Alberta government also reviewed its output ceilings. Fitzgerald wrote, “…the government ensured that oil sands production could go ahead without limitation, to serve markets which were not met by conventional suppliers”. A revised application for an 80,000 b/d plant was submitted in 1968. A year later Syncrude was approved with production to begin in 1976. This was possible because pipeline capacity had been expanded.

But nothing has even been easy. Major partner Atlantic Richfield (ARCO) pulled out in 1974 in part because of its financial commitments to the Prudhoe Bay oil discovery and the Trans Alaska pipeline. Syncrude’s estimated costs were skyrocketing and another private sector partner could not be secured. But because of OPEC and concerns about world oil supplies, the governments of Alberta, Ontario and Canada bought the 30% interest abandoned by ARCO. Syncrude started mining and processing oil sands in 1978.

In 1974 governments invested taxpayer funds to ensure Canadians always had access to oil. Today these same governments take turns either bashing, taxing, regulating or obstructing the oil business.

Adding pipeline capacity this century has been successful and impossible. Total crude production (conventional plus oil sands) from western Canada rose from 1.9 b/d in 2000 to 3.7 million b/d in 2017. This required a lot of pipe and still does. Oil production expansion projects have been delayed or cancelled because of market access challenges. Several international operators have sold their oil sands properties to invest their money in places without Canada’s self-inflicted obstacles.

Contrary to revisionist political spin from Ottawa and Edmonton, under Prime Minister Stephen Harper a lot of export pipe was approved, built and is now operating. This included the original Keystone line in 2010, (600,000 b/d), Alberta Clipper in 2010, (500,000 b/d) and some modifications to the existing Enbridge system to carry more oil in 2016 (300,000 b/d).

But thanks to fossil fuel opponents and sympathetic politicians, more pipe capacity has been rejected than built. Northern Gateway was approved by the Harper administration in 2012 but officially killed by the current Liberal government in 2016. Former U.S. President Obama terminated Keystone XL in 2015. TransCanada Corporation gave up on Energy East in 2017 after new federal approval processes made the timelines and outcome unworkable and unknown.

When operating, those three lines would have carried over 2 million b/d. Assured, safe, reliable and low-cost pipeline takeaway capacity would have significantly changed the decisions of oil sands developers in the past five years. The anti-carbon movement has been very successful in inflicting significant economic damage, but only in Canada.

Prime Minister Trudeau and Alberta Premier Notley are taking enormous credit for the still-pending Trans Mountain expansion. This issue was so badly bungled Ottawa had to buy Trans Mountain from Kinder Morgan to ensure it wouldn’t die. That Enbridge could replace Line 3 for safety reasons and to increase capacity was triumphantly approved in 2016 by Ottawa. Keystone XL was revived by U.S. President Trump after he was elected in late 2016.

The Canadian application dates for these three projects were 2012, 2014 and 2008 respectively. Realistically, not one of these will carry a barrel of oil before 2020 despite what official announcements may state.

Geography has always been an obstacle for western Canada’s oil industry. Oil’s enemies figured out how to exploit the pipeline approval process and climate change alarmism to obstruct continued output growth long before the industry fully understood they might be successful.

The end game of the anti-carbon movement, articulated by David “Leave It In The Ground” Suzuki, is the decarbonization of the economy. Alberta’s oil sands remain at the top of the list. If successful, this will hurt.

More to come.

David Yager is a consulting oil service executive advisor and has been an analyst and commentator on the oil industry and energy policy since 1979. He is currently working on a book planned for publication in 2019.

ABOUT ENERGYNOW

EnergyNow is an online energy news and data media service dedicated to providing essential up to-date information on the Canadian oil & gas industry.

We provide live feeds designed to help energy professionals, field personnel, business owners, and senior business leaders get the latest energy news and data, energy industry press releases and energy job and event listings.